Methods and Compositions for Screenless Completion

ABSTRACT

Methods are provided that include a method of a) placing a hydrojetting tool into a subterranean formation; b) introducing a jetting fluid that includes an aqueous base fluid, a stabilizing agent, and a cutting agent into the subterranean formation by use of the hydrojetting tool at a rate sufficient to create at least one fracture; c) introducing a slug fluid that includes an aqueous base fluid and a degradable diverting agent into an annulus formed between the hydrojetting tool and the subterranean formation; d) introducing a propping fluid that includes an aqueous base fluid and proppants coated with a consolidating agent into the annulus formed between the hydrojetting tool and the subterranean formation; and e) placing the proppants in the fracture.

BACKGROUND

The present invention relates to completion operations, and in particular, to subterranean fluids, tools, and methods useful during screenless completion of a fractured subterranean formation.

Hydraulic fracturing is a technique in which fractures are propagated in a rock layer for the eventual purpose of extracting certain fluids such as petroleum, natural gas, coal seam gas, and the like. The technique can be used to increase or restore the rate at which these fluids can be produced from a subterranean formation. Hydraulic fracturing can be particularly useful in the completion of unconsolidated or loosely consolidated formations where relatively fine particulate materials may be produced during the production of fluids. These particulates may cause, for example, abrasive wear to components such as screens, tubing, pumps, and valves. The particulates may also clog a well, thus creating the need for expensive workovers. Additionally, if the particulates are produced to the surface, they may have to be removed using surface processing equipment.

Conventional methods for preventing the production of such particulate materials include, for example, gravel packing the well adjacent to the unconsolidated or loosely consolidated production interval. A sand control screen (or “gravel-pack screen”) is a filter assembly that can be used to support and retain the sand placed during a gravel pack operation. A sand control screen may be lowered into a wellbore on a work string and precisely positioned relative to the desired production interval. Next, a fluid slurry that includes gravel is pumped down the work string and into the well annulus formed between the sand control screen and the perforated well casing or open hole production zone.

In some cases, an operator may choose to combine the processes of hydraulic fracturing and gravel packing into a unified treatment that can stimulate production while providing an annular gravel pack for sand control. Such treatments may be referred to as “frac pack operations.” Frac pack operations may be conducted with a gravel pack screen assembly in place, by pumping the fracturing fluid through an annular space between the screen and casing (or between the screen and the walls of the well bore, in “open hole” wells that are completed without casing). In such cases, the frac pack operation may ultimately terminate in a condition referred to as “screen out” that creates an annular gravel pack between the screen and casing (or between the screen and the well bore walls, in open hole wells). This allows both fracturing and gravel packing to be performed in a single operation. Thus, frac pack is a technique that combines the stimulation advantages of a highly conductive hydraulic fracture with sand control of a gravel pack to improve productivity in certain subterranean formations. Tools associated with frac packing may include, for example, setting packers, isolating tools, and the like.

Moreover, it is sometimes desirable to stimulate or frac pack multiple hydrocarbon-bearing zones so that multiple formations may be produced simultaneously, yet separately. When multiple hydrocarbon-bearing zones are stimulated by hydraulic fracturing or frac packing, economic and technical gains maybe be realized by injecting multiple treatment stages that can be diverted (or separated) by various means, including mechanical devices such as bridge plugs, packers, downhole valves, sliding sleeves, and baffle/plug combinations; ball sealers; particulates such as sand, ceramic material, proppant, salt, waxes, resins, or other compounds; or by alternative fluid systems such as viscosified fluids, gelled fluids, foams, or other chemically formulated fluids; or using limited entry methods.

However, there are certain issues that limit or impact the overall usefulness of gravel packing and sand control screens, particularly when stimulating multiple hydrocarbon-bearing zones. For example, in fracturing operations, the fluid inside sand control screens tends to leak off into adjacent formations. This leak off can result in damage to the gravel pack around the sand control screen as well as damage to the formation. This problem may be particularly troublesome in situations where multiple production intervals within a single wellbore require treatment as the fluid remains in communication with the various formations for an extended period time. Sand control screens may require precise placement inside a wellbore so as to fully cover the formation zone as needed. Moreover, the process of achieving complete separation of fluids during multiple zone completion can present a technical barrier.

SUMMARY OF THE INVENTION

The present invention relates to completion operations, and in particular, to subterranean fluids, tools, and methods useful during screenless completion of a fractured subterranean formation.

In some embodiments, the present invention provides methods comprising: a) placing a hydrojetting tool into a subterranean formation; b) introducing a jetting fluid comprising an aqueous base fluid, a stabilizing agent, and a cutting agent into the subterranean formation by use of the hydrojetting tool at a rate sufficient to create at least one fracture; c) introducing a slug fluid comprising an aqueous base fluid and a degradable diverting agent into an annulus formed between the hydrojetting tool and the subterranean formation; d) introducing a propping fluid comprising an aqueous base fluid and proppants coated with a consolidating agent into the annulus formed between the hydrojetting tool and the subterranean formation; and e) placing the proppants in the fracture.

In other embodiments, the present invention provides methods comprising: a) placing a hydrojetting tool into a wellbore; b) introducing a jetting fluid comprising an aqueous base fluid, a stabilizing agent, and a cutting agent into the wellbore by use of the hydrojetting tool at a rate sufficient to create at least one fracture; c) introducing a slug fluid comprising an aqueous base fluid and a degradable diverting agent into an annulus formed between the hydrojetting tool and the wellbore; d) introducing a propping fluid comprising an aqueous base fluid and proppants coated with a consolidating agent into the annulus formed between the hydrojetting tool and the wellbore; e) placing the proppants into the fracture; f) repositioning the hydrojetting tool to a different interval or zone within the wellbore; and g) repeating steps b), c), d) and e).

The features and advantages of the present invention will be readily apparent to those skilled in the art upon a reading of the description of the preferred embodiments that follows.

DETAILED DESCRIPTION

The present invention relates to completion operations, and in particular, to subterranean fluids, tools, and methods useful during screenless completion of a fractured subterranean formation.

The present invention, in some embodiments, provides methods for performing multiple frac pack completions across multiple formation zones without the use of certain tools. For example, the present invention may be practiced without the need for setting packers, isolating tools, and screens, which are typically used in conventional frac packing. Consequently, the present invention may allow an operator to freely access the wellbore at any time without the need to remove certain workstrings and/or downhole tools.

In some embodiments, multiple frac pack completions across multiple formation zones may be performed within a single trip of the completion tools. In some embodiments, the present invention efficiently performs multiple frac pack completions without the need for separate gravel packing. By contrast, conventional frac packing may require complete packing of gravel, otherwise the sand control screen can become damaged.

In one or more embodiments, the methods of the present invention may be more economical and/or less time consuming as compared with conventional frac pack techniques. In some embodiments, the present invention provides superior leak-off control coverage as compared to conventional frac pack methods, which can lead to improved fracture(s) generation, proppant placement, and well production. According to some embodiments, the present invention can stabilize the formation surrounding or adjacent to the fracture faces or perforations, which can lead to reduction in fines migration.

Some embodiments of the present invention provide methods comprising: a) placing a hydrojetting tool into a subterranean formation; b) introducing a jetting fluid comprising an aqueous base fluid, a stabilizing agent, and a cutting agent into the subterranean formation by use of the hydrojetting tool at a rate sufficient to create at least one fracture; c) introducing a slug fluid comprising an aqueous base fluid and a degradable diverting agent into an annulus formed between the hydrojetting tool and the subterranean formation; d) introducing a propping fluid comprising an aqueous base fluid and proppants coated with a consolidating agent into the annulus formed between the hydrojetting tool and the subterranean formation; e) and placing the proppants in the fracture.

In some embodiments, the jetting fluid may create a perforation or a slot. Optionally, the methods may further comprise: f) repositioning the hydrojetting tool to a different interval or zone within the subterranean formation; and g) repeating steps b), c), d), and e).

For many wellbores, an essential step during completion is to make a connection between the wellbore and the formation. This is often done by creating perforations with perforation guns or hydrojetting tools to blast holes in casings or liners to make a connection. Hydrojetting fracturing methods are described in U.S. Pat. Nos. 5,765,642, 7,225,869, and 7,766,083, which are incorporated in their entirety herein by reference. As used herein, the term “perforation” refers to a hole created in the casing or liner of an oil well to connect it to the reservoir. As used herein, the term “hydrojetting tool” or “hydrojetting tool” can include any tool comprising at least one jet-forming nozzle. As used herein, the term “fluid jet forming nozzle” refers to any fixture that may be coupled to an aperture so as to allow the communication of a fluid therethrough such that the fluid velocity exiting the jet is higher than the fluid velocity at the entrance of the jet. Such a nozzle may be used to eject a fluid in a coherent stream. Suitable examples of hydrojetting tools are described in U.S. Pat. No. 5,765,642, the entire disclosure of which is hereby incorporated by reference. As used herein, the term “hydrojetting” may refer to a process of controlling high pressure fluid jets with accuracy. Hydrojetting tools can be placed in a wellbore to create a high pressure fluid flow path directed at a formation site. A hydrojetting tool may be used to form, for example, a perforation, a slot, and/or a notch, opening, or tunnel in the formation from which a fracture is created.

The hydrojetting tool may take a variety of different forms. A hydrojetting tool may generally include an axial fluid flow passage extending therethrough and communicating with at least one angularly spaced lateral port diposed through the sides of the hydrojetting tool. The fluid jet forming nozzle may be connected within each of the lateral ports. In some embodiments, the hydrojetting tool comprises and/or is coupled to a work string such as coiled tubular (“coiled tubing”) or a jointed pipe. In some embodiments, the jet-forming nozzle may be attached to the coiled tubular or the jointed pipe. The coiled tubular or the jointed pipe may lower the hydrojetting tool into a wellbore and may supply the hydrojetting tool with a subterranean treatment fluid.

Generally, the hydrojetting tool of the present invention may be lowered into a subterranean formation (e.g., a producing zone of a formation) by any suitable means. For example, the hydrojetting tool of the present invention may be attached or otherwise coupled to a workstring which may lower the hydrojetting tool in a wellbore. The wellbore may be vertical, horizontal, or any combination thereof. For example, the use of coiled tubular allows the hydrojetting tool to be easily lowered into wellbores that may be substantially deviated in certain zones. The work string may also be used to move and position the hydrojetting tool to different locations in the wellbore. Generally, the hydrojetting tool and/or the workstring will have a diameter that is smaller than the diameter of the wellbore. Thus, the hydrojetting tool and the subterranean formation may define an annulus (i.e., empty space) once the hydrojetting tool is lowered in the wellbore.

The hydrojetting tool may generally be used to introduce fluids into the subterranean formation. In some embodiments, the hydrojetting tool may introduce fluids through its jet forming nozzle. In other embodiments, the hydrojetting tool may include an opening through which fluids may be introduced into the subterranean formation. In some embodiments, the fluids may be introduced into the annulus defined by the hydrojetting tool and the wellbore. In some embodiments, the fluids may be introduced into the annulus defined by a perforated casing and the wellbore.

Jetting fluids of the present invention may be used to create at least one fracture in the subterranean formation. In some embodiments, jetting fluids may be used to create at least one perforation or slot and a notch in the formation from which a fracture is formed in the subterranean formation. The perforation or slot may be formed on a casing and/or wellbore depending on the particular configuration of the wellbore. The jetting fluids of the present invention generally comprise an aqueous base fluid, a stabilizing agent, and a cutting agent. Optionally, the jetting fluids may further comprise a clay stabilizer, a scale inhibitor, a corrosion inhibitor, a biocide, a surfactant, a gas hydrate inhibitor, and any combination thereof.

The aqueous base fluid used in the subterranean treatment fluids (e.g., jetting fluid, slug fluid, propping fluid) of the present invention can comprise any suitable aqueous fluid known to one of ordinary skill in the art. Suitable aqueous fluids may include, but are not limited to, fresh water, saltwater (e.g., water containing one or more salts dissolved therein), glycol, brine (e.g., saturated saltwater), weighted brine (e.g., an aqueous solution of sodium bromide, calcium bromide, zinc bromide and the like), and any combination thereof. Generally, the aqueous fluid may be from any source, provided that it does not contain components that might adversely affect the stability and/or performance of the jetting fluids of the present invention.

Stabilizing agents of the present invention are used to minimize particulate migration in subterranean formations. In some preferred embodiments, the stabilizing agents are water-based. Suitable stabilizing agents may include, but are not limited to, non-aqueous tackifying agents, aqueous tackifying agents, emulsified tackifying agents, silyl-modified polyamide compounds, resins, crosslinkable aqueous polymer compositions, polymerizable organic monomer compositions, stabilizing agent emulsions, zeta-potential modifying aggregating compositions, and binders. Combinations and/or derivatives of these also may be suitable. Nonlimiting examples of suitable non-aqueous tackifying agents may be found in U.S. Pat. Nos. 5,853,048; 5,839,510; and 5,833,000 as well as U.S. Patent Application Publication Nos. 2007/0131425 and 2007/0131422, the entire disclosures of which are herein incorporated by reference. Nonlimiting examples of suitable aqueous tackifying agents may be found in U.S. Pat. Nos. 5,249,627 and 4,670,501 as well as U.S. Patent Application Publication Nos. 2005/0277554 and 2005/0274517, the entire disclosures of which are herein incorporated by reference. Nonlimiting examples of suitable crosslinkable aqueous polymer compositions may be found in U.S. Patent Application Publication Nos. 2010/0160187 and 2011/0030950, the entire disclosures of which are herein incorporated by reference. Nonlimiting examples of suitable silyl-modified polyamide compounds may be found in U.S. Pat. No. 6,439,309, the entire disclosure of which is herein incorporated by reference. Nonlimiting examples of suitable resins may be found in U.S. Pat. Nos. 7,673,686, 7,153,575, 6,677,426, 6,582,819, 6,311,773, and 4,585,064 as well as U.S. Patent Application Publication Nos. 2010/0212898 and 2008/0006405, the entire disclosures of which are herein incorporated by reference. One of skill in the art should recognize that a non-aqueous resin may be used as a water-external emulsion where desired. Nonlimiting examples of suitable polymerizable organic monomer compositions may be found in U.S. Pat. No. 7,819,192, the entire disclosure of which is herein incorporated by reference. Nonlimiting examples of suitable stabilizing agent emulsions may be found in U.S. Patent Application Publication No. 2007/0289781 the entire disclosure of which is herein incorporated by reference. Nonlimiting examples of suitable zeta-potential modifying aggregating compositions may be found in U.S. Pat. Nos. 7,956,017 and 7,392,847 the entire disclosures of which are herein incorporated by reference. Nonlimiting examples of suitable binders may be found in U.S. Pat. Nos. 8,003,579, 7,825,074, and 6,287,639 as well as U.S. Patent Application Publication No. 2011/0039737, the entire disclosures of which are herein incorporated by reference. It is within the ability of one skilled in the art, with the benefit of this disclosure, to determine the type and amount of stabilizing agent to include in the methods of the present invention to achieve the desired results.

The cutting agents of the present invention may be used as abrasives within the jetting fluid. An abrasive may enhance the cutting action (i.e., formation of perforations) of the jetting fluid when used with the hydrojetting tool. Suitable cutting agents compatible with one or more embodiments of the present invention may include any small particulate with a coarse surface such as cutting sand. Suitable particulates may include, but are not limited to, bauxite, ceramic materials, glass materials, polymer materials, nut shell pieces, cured resinous particulates comprising nut shell pieces, seed shell pieces, cured resinous particulates comprising seed shell pieces, fruit pit pieces, cured resinous particulates comprising fruit pit pieces, wood, composite particulates, and combinations thereof. Typically, the cutting agent will be present in relatively low concentrations. In some embodiments, the cutting agent may be present in an amount ranging from about 0.1% to about 10% by weight of the jetting fluid. In some embodiments, the particle size of the cutting agents may range from about 100 mesh to about 20 mesh.

The slug fluids of the present invention may be used to extend a fracture into the formation. In some embodiments, the slug fluid may be introduced into the annulus formed by the hydrojetting tool and the formation at a rate sufficient to raise the annular pressure (i.e., the pressure exerted by the slug fluid) to a level sufficient to extend the fracture.

In some embodiments, the slug fluid may be introduced into the subterranean formation, for example, through the annulus defined by the hydrojetting tool and the subterranean formation. The slug fluids generally comprise an aqueous base fluid and a degradable diverting agent. The aqueous base fluid may be any fluid known in the art suitable for use as a slug fluid, including those mentioned above for use in other treatment fluids of the present invention (e.g., jetting fluid, propping fluid).

The degradable diverting agents used in the slug fluid of the present invention are solid materials used to provide a desired amount of fluid loss control in the subterranean formation. For example, fluid loss may be controlled such that the annular pressure (i.e., pressure between the hydrojetting tool and the formation) is raised to a level sufficient to help extend the fracture. Suitable degradable diverting agents include, but are not limited to, polysaccharides such as dextran or cellulose; chitins; chitosans; proteins; aliphatic polyesters; poly(lactides); poly(glycolides); poly(ε-caprolactones); poly(hydroxybutyrates); poly(anhydrides); aliphatic polycarbonates; poly(orthoesters); poly(amino acids); poly(ethylene oxides); polyphosphazenes; derivatives thereof; and combinations thereof. In some embodiments, the degradable diverting agent may be self-degradable. In some embodiments, the degradable diverting agent may degrade prior to or during well production.

As used herein, the terms “degrade,” “degradation,” “degradable,” and the like refer to a material's tendency to be broken down into simpler components. In some embodiments, a degradable material may be broken down chemically by the addition of another material. As used herein, the term “self-degrade,” “self-degradation,” “self-degradable,” and the like generally refer to the tendency of a composition to degrade over time when placed in a subterranean zone through natural means (e.g., air, light, water, and the like). Degradation may generally take place by any suitable means including, but not limited to, hydrolytic degradation, surface erosion, bulk erosion, and the like.

In some embodiments, the degradable diverting agent has a particle size distribution in the range of about 0.1 micron to about 1 mm. In some embodiments, the degradable diverting agent may be present in the range of from about 0.1% to about 10% by weight of the slug fluid, preferably in an amount in the range of from about 0.2% to about 0.5% by weight of the slug fluid.

The propping fluids of the present invention are generally used to introduce proppants into fractures where the proppants may be deposited. The propping fluids generally comprise an aqueous base fluid and proppants coated with a consolidating agent. In some embodiments, the propping fluid may be viscosified by a gelling agent and a crosslinker. In some embodiments, the propping fluids may be introduced into the subterranean formation through the annulus defined by the hydrojetting tool and the subterranean formation.

The gelling agents suitable for use in the present invention may comprise any substance (e.g., a polymeric material) capable of increasing the viscosity of the treatment fluid. In certain embodiments, the gelling agent may comprise one or more polymers that have at least two molecules that are capable of forming a crosslink in a crosslinking reaction in the presence of a crosslinking agent, and/or polymers that have at least two molecules that are so crosslinked (i.e., a crosslinked gelling agent). The gelling agents may be naturally-occurring gelling agents, synthetic gelling agents, or a combination thereof. The gelling agents also may be cationic gelling agents, anionic gelling agents, or a combination thereof. Suitable gelling agents include, but are not limited to, polysaccharides, biopolymers, and/or derivatives thereof that contain one or more of these monosaccharide units: galactose, mannose, glucoside, glucose, xylose, arabinose, fructose, glucuronic acid, or pyranosyl sulfate. Examples of suitable polysaccharides include, but are not limited to, guar gums (e.g., hydroxyethyl guar, hydroxypropyl guar, carboxymethyl guar, carboxymethylhydroxyethyl guar, and carboxymethylhydroxypropyl guar (CMHPG)), cellulose derivatives (e.g., hydroxyethyl cellulose, carboxyethylcellulose, carboxymethylcellulose, and carboxymethylhydroxyethylcellulose), xanthan, scleroglucan, succinoglycan, diutan, and combinations thereof. In certain embodiments, the gelling agents comprise an organic carboxylated polymer, such as CMHPG.

Suitable synthetic polymers include, but are not limited to, 2,2′-azobis(2,4-dimethyl valeronitrile), 2,2′-azobis(2,4-dimethyl-4-methoxy valeronitrile), polymers and copolymers of acrylamide ethyltrimethyl ammonium chloride, acrylamide, acrylamido- and methacrylamido-alkyl trialkyl ammonium salts, acrylamidomethylpropane sulfonic acid, acrylamidopropyl trimethyl ammonium chloride, acrylic acid, dimethylaminoethyl methacrylamide, dimethylaminoethyl methacrylate, dimethylaminopropyl methacrylamide, dimethylaminopropylmethacrylamide, dimethyldiallylammonium chloride, dimethylethyl acrylate, fumaramide, methacrylamide, methacrylamidopropyl trimethyl ammonium chloride, methacrylamidopropyldimethyl-n-dodecylammonium chloride, methacrylamidopropyldimethyl-n-octylammonium chloride, methacrylamidopropyltrimethylammonium chloride, methacryloylalkyl trialkyl ammonium salts, methacryloylethyl trimethyl ammonium chloride, methacrylylamidopropyldimethylcetylammonium chloride, N-(3-sulfopropyl)-N-methacrylamidopropyl-N,N-dimethyl ammonium betaine, N,N-dimethylacrylamide, N-methylacrylamide, nonylphenoxypoly(ethyleneoxy)ethylmethacrylate, partially hydrolyzed polyacrylamide, poly 2-amino-2-methyl propane sulfonic acid, polyvinyl alcohol, sodium 2-acrylamido-2-methylpropane sulfonate, quaternized dimethylaminoethylacrylate, quaternized dimethylaminoethylmethacrylate, and derivatives and combinations thereof. In certain embodiments, the gelling agent comprises an acrylamide/2-(methacryloyloxy)ethyltrimethylammonium methyl sulfate copolymer. In certain embodiments, the gelling agent may comprise an acrylamide/2-(methacryloyloxy)ethyltrimethylammonium chloride copolymer. In certain embodiments, the gelling agent may comprise a derivatized cellulose that comprises cellulose grafted with an allyl or a vinyl monomer, such as those disclosed in U.S. Pat. Nos. 4,982,793, 5,067,565, and 5,122,549, the entire disclosures of which are incorporated herein by reference.

Additionally, polymers and copolymers that comprise one or more functional groups (e.g., hydroxyl, cis-hydroxyl, carboxylic acids, derivatives of carboxylic acids, sulfate, sulfonate, phosphate, phosphonate, amino, or amide groups) may be used as gelling agents.

The gelling agent may be present in the propping fluids in an amount sufficient to provide the desired viscosity. In some embodiments, the gelling agents (i.e., the polymeric material) may be present in an amount in the range of from about 0.1% to about 10% by weight of the propping fluid. In certain embodiments, the gelling agents may be present in an amount in the range of from about 0.15% to about 2.5% by weight of the propping fluid.

In those embodiments of the present invention where it is desirable to crosslink the gelling agent, the propping fluid may comprise one or more crosslinking agents. The crosslinking agents may comprise a borate ion, a metal ion, or similar component that is capable of crosslinking at least two molecules of the gelling agent. Examples of suitable crosslinking agents include, but are not limited to, borate ions, magnesium ions, zirconium IV ions, titanium IV ions, aluminum ions, antimony ions, chromium ions, iron ions, copper ions, magnesium ions, and zinc ions. These ions may be provided by providing any compound that is capable of producing one or more of these ions. Examples of such compounds include, but are not limited to, ferric chloride, boric acid, disodium octaborate tetrahydrate, sodium diborate, pentaborates, ulexite, colemanite, magnesium oxide, zirconium lactate, zirconium triethanol amine, zirconium lactate triethanolamine, zirconium carbonate, zirconium acetylacetonate, zirconium malate, zirconium citrate, zirconium diisopropylamine lactate, zirconium glycolate, zirconium triethanol amine glycolate, zirconium lactate glycolate, titanium lactate, titanium malate, titanium citrate, titanium ammonium lactate, titanium triethanolamine, and titanium acetylacetonate, aluminum lactate, aluminum citrate, antimony compounds, chromium compounds, iron compounds, copper compounds, zinc compounds, and combinations thereof. In certain embodiments of the present invention, the crosslinking agent may be formulated to remain inactive until it is “activated” by, among other things, certain conditions in the fluid (e.g., pH, temperature, etc.) and/or interaction with some other substance. In some embodiments, the activation of the crosslinking agent may be delayed by encapsulation with a coating (e.g., a porous coating through which the crosslinking agent may diffuse slowly, or a degradable coating that degrades downhole) that delays the release of the crosslinking agent until a desired time or place. The choice of a particular crosslinking agent will be governed by several considerations that will be recognized by one skilled in the art, including but not limited to, the type of gelling agent included, the molecular weight of the gelling agent, the conditions in the subterranean formation being treated, the safety handling requirements, the pH of the treatment fluid, temperature, and/or the desired delay for the crosslinking agent to crosslink the gelling agent molecules.

When included, suitable crosslinking agents may be present in the propping fluids of the present invention in an amount sufficient to provide the desired degree of crosslinking between molecules of the gelling agent. In certain embodiments, the crosslinking agent may be present in propping fluids of the present invention in an amount in the range of from about 0.005% to about 1% by weight of the propping fluid. In certain embodiments, the crosslinking agent may be present in the propping fluids of the present invention in an amount in the range of from about 0.05% to about 1% by weight of the propping fluid. One of ordinary skill in the art, with the benefit of this disclosure, will recognize the appropriate amount of crosslinking agent to include in the propping fluid of the present invention based on, among other things, the temperature conditions of a particular application, the type of gelling agents used, the molecular weight of the gelling agents, the desired degree of viscosification, and/or the pH of the treatment fluid.

Suitable proppants used in accordance with one or more embodiments of the present invention include, but are not limited to, sand, bauxite, ceramic materials, glass materials, polymer materials, polytetrafluoroethylene materials, nut shell pieces, cured resinous particulates comprising nut shell pieces, seed shell pieces, cured resinous particulates comprising seed shell pieces, fruit pit pieces, cured resinous particulates comprising fruit pit pieces, wood, composite particulates, and combinations thereof. Suitable composite particulates may comprise a binder and a filler material wherein suitable filler materials include silica, alumina, fumed carbon, carbon black, graphite, mica, titanium dioxide, meta-silicate, calcium silicate, kaolin, talc, zirconia, boron, fly ash, hollow glass microspheres, solid glass, and combinations thereof. The mean proppant size generally may range from about 4 mesh to about 100 mesh on the U.S. Sieve Series; however, in certain circumstances, other mean proppant sizes may be desired and will be entirely suitable for practice of the present invention. In particular embodiments, mean proppant size distribution ranges are one or more of 6/12, 8/16, 12/20, 16/30, 20/40, 30/50, 40/60, 40/70, or 50/70 mesh. In the preferred embodiment, the proppant may be in the range of about 10 to about 60 mesh. It should be understood that the term “proppant,” as used in this disclosure, includes all known shapes of materials, including substantially spherical materials, fibrous materials, polygonal materials (such as cubic materials), and combinations thereof. Moreover, fibrous materials, that may or may not be used to bear the pressure of a closed fracture, may be included in certain embodiments of the present invention. Suitable fibrous material may include, but is not limited to, natural and synthetic fibers, inorganic fibers, glass fibers, carbon fibers, synthetic polymer fibers, ceramic fibers, metal fibers, and combinations thereof. Examples of suitable fibrous materials are described in U.S. Pat. Nos. 6,172,011 and 5,551,514, which are incorporated in their entirety herein by reference. In certain embodiments, the proppants may be present in the propping fluids of the present invention in an amount in the range of from about 0.5 pounds per gallon (“ppg”) to about 30 ppg by volume of the propping fluid.

In some embodiments, the proppant may be pre-coated with a consolidating agent(s) and/or coated on-the-fly with a consolidating agent(s) during the operation at well site. In some embodiments, the consolidating agent may be coated early in the proppant stage of the fracturing treatment. In some embodiments, the coated proppants may be used during the tail-in stage of the fracturing treatment. In some embodiments, the consolidating agent(s) are coated intermittently on the proppants. Generally, any portion of the proppant may be coated. In one or more embodiments, at least a majority of the proppants are coated with a curable resin, which can consolidate in situ to form a hardenable mass. Suitable examples of consolidating agents may include, but are not limited to, epoxies, furans, phenolics, furfuryl aldehydes, furfuryl alcohols, silicon-based resins, non-aqueous tackifying agents, aqueous tackifying agents, silyl-modified polyamides, curable resin compositions that are capable of curing to form hardened substances, zeta potential-modifying aggregating compositions, fibrous agents, derivatives thereof, and combinations thereof. The non-aqueous tackifying agents, aqueous tackifying agents, silyl-modified polyamides, and curable resin compositions that are capable of curing to form hardened substances described above with reference to the jetting fluid of the present invention are also suitable for use as a consolidating agent in the propping fluid.

In some embodiments, the consolidating agent may comprise an aggregating composition that can modify the zeta potential or aggregation potential of a proppant. Such modifications can permit any two surfaces (e.g., of a proppant and a substrate) to have a greater attraction for one another.

Aggregating compositions suitable for use in the present invention include, but are not limited to, a reaction product of an amine and a phosphate ester, where the aggregating composition is designed to coat a surface with the reaction product to change the zeta potential or aggregation potential of the surface. Suitable aggregating compositions and their methods of use can be found in U.S. Pat. No. 7,392,847, filed Dec. 9, 2005 and U.S. Pat. No. 7,956,017, filed May 6, 2008, the entire disclosures of which are hereby incorporated by reference.

Suitable amines include, but are not limited to, any amine that is capable of reacting with a suitable phosphate ester to form a composition that forms a deformable coating on a surface. Exemplary examples of such amines include, but are not limited to, any amine of the general formula R₁,R₂NH or mixtures or combinations thereof, where R₁ and R₂ are independently a hydrogen atom or a carbyl group having between about 1 and 40 carbon atoms and the required hydrogen atoms to satisfy the valence and where one or more of the carbon atoms can be replaced by one or more hetero atoms selected from the group consisting of boron, nitrogen, oxygen, phosphorus, sulfur or mixture or combinations thereof and where one or more of the hydrogen atoms can be replaced by one or more single valence atoms selected from the group consisting of fluorine, chlorine, bromine, iodine, or mixtures or combinations thereof. Exemplary examples of amines suitable for use in this invention include, but are not limited to, aniline and alkyl anilines or mixtures of alkyl anilines, pyridines and alkyl pyridines or mixtures of alkyl pyridines, pyrrole and alkyl pyrroles or mixtures of alkyl pyrroles, piperidine and alkyl piperidines or mixtures of alkyl piperidines, pyrrolidine and alkyl pyrrolidines or mixtures of alkyl pyrrolidines, indole and alkyl indoles or mixture of alkyl indoles, imidazole and alkyl imidazole or mixtures of alkyl imidazole, quinoline and alkyl quinoline or mixture of alkyl quinoline, isoquinoline and alkyl isoquinoline or mixture of alkyl isoquinoline, pyrazine and alkyl pyrazine or mixture of alkyl pyrazine, quinoxaline and alkyl quinoxaline or mixture of alkyl quinoxaline, acridine and alkyl acridine or mixture of alkyl acridine, pyrimidine and alkyl pyrimidine or mixture of alkyl pyrimidine, quinazoline and alkyl quinazoline or mixture of alkyl quinazoline, or mixtures or combinations thereof.

Suitable phosphate esters include, but are not limited to, any phosphate ester that is capable of reacting with a suitable amine to form a composition that forms a deformable coating on a surface. Exemplary examples of such phosphate esters include, but are not limited to, any phosphate esters of the general formula P(O)(OR³)(OR⁴)(OR⁵) or mixture or combinations thereof, where R³, R⁴, and OR⁵ are independently a hydrogen atom or a carbyl group having between about between about 1 and 40 carbon atoms and the required hydrogen atoms to satisfy the valence and where one or more of the carbon atoms can be replaced by one or more hetero atoms selected from the group consisting of boron, nitrogen, oxygen, phosphorus, sulfur or mixture or combinations thereof and where one or more of the hydrogen atoms can be replaced by one or more single valence atoms selected from the group consisting of fluorine, chlorine, bromine, iodine or mixtures or combinations thereof. Exemplary examples of phosphate esters include, but are not limited to, phosphate ester of alkanols having the general formula P(O)(OH)_(x)(OR⁶)_(y) where x+y=3 and are independently a hydrogen atom or a carbyl group having between about 1 and 40 carbon atoms and the required hydrogen atoms to satisfy the valence and where one or more of the carbon atoms can be replaced by one or more hetero atoms selected from the group consisting of boron, nitrogen, oxygen, phosphorus, sulfur or mixture or combinations thereof and where one or more of the hydrogen atoms can be replaced by one or more single valence atoms selected from the group consisting of fluorine, chlorine, bromine, iodine or mixtures or combinations thereof such as ethoxy phosphate, propoxyl phosphate or higher alkoxy phosphates or mixtures or combinations thereof. Other exemplary examples of phosphate esters include, but are not limited to, phosphate esters of alkanol amines having the general formula N[R⁷OP(O)(OH)₂]₃ where R⁷ is a carbenzyl group having between about 1 and 40 carbon atoms and the required hydrogen atoms to satisfy the valence and where one or more of the carbon atoms can be replaced by one or more hetero atoms selected from the group consisting of boron, nitrogen, oxygen, phosphorus, sulfur or mixture or combinations thereof and where one or more of the hydrogen atoms can be replaced by one or more single valence atoms selected from the group consisting of fluorine, chlorine, bromine, iodine or mixtures or combinations thereof. Other exemplary examples of phosphate esters include, but are not limited to, phosphate esters of hydroxylated aromatics such as phosphate esters of alkylated phenols such as Nonylphenyl phosphate ester or phenolic phosphate esters. Other exemplary examples of phosphate esters include, but are not limited to, phosphate esters of diols and polyols such as phosphate esters of ethylene glycol, propylene glycol, or higher glycolic structures. Other exemplary phosphate esters include, but are not limited to, any phosphate ester than can react with an amine and coated on to a substrate forms a deformable coating enhancing the aggregating potential of the substrate.

Therefore, the present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered, combined, or modified and all such variations are considered within the scope and spirit of the present invention. The invention illustratively disclosed herein suitably may be practiced in the absence of any element that is not specifically disclosed herein and/or any optional element disclosed herein. While compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the element that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted. 

The invention claimed is:
 1. A method comprising: a) placing a hydrojetting tool into a subterranean formation; b) introducing a jetting fluid comprising an aqueous base fluid, a stabilizing agent, and a cutting agent into the subterranean formation by use of the hydrojetting tool at a rate sufficient to create at least one fracture; c) introducing a slug fluid comprising an aqueous base fluid and a degradable diverting agent into an annulus formed between the hydrojetting tool and the subterranean formation; d) introducing a propping fluid comprising an aqueous base fluid and proppants coated with a consolidating agent into the annulus formed between the hydrojetting tool and the subterranean formation; and e) placing the proppants in the fracture.
 2. The method of claim 1, wherein the hydrojetting tool comprises at least one jet-forming nozzle.
 3. The method of claim 1 further comprising: f) repositioning the hydrojetting tool to a different interval or zone within the subterranean formation; and g) repeating steps b), c), d) and e).
 4. The method of claim 1, wherein the hydrojetting tool is a coiled tubular or a jointed pipe.
 5. The method of claim 1, wherein the stabilizing agent comprises a non-aqueous tackifying agent; an aqueous tackifying agent; a silyl-modified polyamide; a curable resin composition, or any combination thereof.
 6. The method of claim 1, wherein the cutting agent is selected from the group consisting of cutting sand, proppant, and any combination thereof.
 7. The method of claim 1, wherein the degradable diverting agent is selected from the group consisting of dextran, cellulose, chitin, protein, aliphatic polyester, poly(lactide), poly(glycolide), poly(ε-caprolactone), poly(hydroxybutyrate), poly(anhydride), aliphatic polycarbonate, poly(orthoester), poly(amino acid), poly(ethylene oxide), polyphosphazene, any derivative thereof, and any combination thereof.
 8. The method of claim 1, wherein the proppants are selected from the group consisting of sand, ground walnut hull, bauxite, ceramic, polymer, any derivative thereof, and any combination thereof.
 9. The method of claim 1, wherein the proppants are pre-coated with the consolidating agent or coated on-the-fly with the consolidating agent.
 10. The method of claim 1, wherein the consolidating agent is selected from the group consisting of an epoxy, a furan, a phenolic, a furfuryl aldehyde, a furfuryl alcohol, a silicon-based resin, a non-aqueous tackifying agent, an aqueous tackifying agent, a silyl-modified polyamide, a curable resin composition, a zeta potential-modifying aggregating composition, a fibrous agent, derivatives thereof, and combinations thereof.
 11. The method of claim 1, wherein the jetting fluid further comprises an additive selected from the group consisting of a clay stabilizer, a scale inhibitor, a corrosion inhibitor, a biocide, a surfactant, a gas hydrate inhibitor, and any combination thereof.
 12. A method comprising: a) placing a hydrojetting tool into a wellbore; b) introducing a jetting fluid comprising an aqueous base fluid, a stabilizing agent, and a cutting agent into the wellbore by use of the hydrojetting tool at a rate sufficient to create at least one fracture; c) introducing a slug fluid comprising an aqueous base fluid and a degradable diverting agent into an annulus formed between the hydrojetting tool and the wellbore; d) introducing a propping fluid comprising an aqueous base fluid and proppants coated with a consolidating agent into the annulus formed between the hydrojetting tool and the wellbore; e) placing the proppants into the fracture; f) repositioning the hydrojetting tool to a different interval or zone within the wellbore; and g) repeating steps b), c), d) and e).
 13. The method of claim 12, wherein the hydrojetting tool comprises at least one jet-forming nozzle.
 14. The method of claim 12, wherein the hydrojetting tool is a coiled tubular or a jointed pipe.
 15. The method of claim 12, wherein the stabilizing agent comprises a non-aqueous tackifying agent; an aqueous tackifying agent; a silyl-modified polyamide; a curable resin composition, or any combination thereof.
 16. The method of claim 12, wherein the cutting agent is selected from the group consisting of cutting sand, proppant, and any combination thereof.
 17. The method of claim 12, wherein the degradable diverting agent is selected from the group consisting of dextran, cellulose, chitin, protein, aliphatic polyester, poly(lactide), poly(glycolide), poly(ε-caprolactone), poly(hydroxybutyrate), poly(anhydride), aliphatic polycarbonate, poly(orthoester), poly(amino acid), poly(ethylene oxide), polyphosphazene, any derivative thereof, and any combination thereof.
 18. The method of claim 12, wherein the proppants are selected from the group consisting of sand, ground walnut hull, bauxite, ceramic, polymer, and any combination thereof.
 19. The method of claim 12, wherein the consolidating agent is selected from the group consisting of an epoxy, a furan, a phenolic, a furfuryl aldehyde, a furfuryl alcohol, a silicon-based resin, a non-aqueous tackifying agent, an aqueous tackifying agent, a silyl-modified polyamide, a curable resin composition, a zeta potential-modifying aggregating composition, a fibrous agent, derivatives thereof, and combinations thereof.
 20. The method of claim 12, wherein the jetting fluid further comprises an additive selected from the group consisting of a clay stabilizer, a scale inhibitor, a corrosion inhibitor, a biocide, a surfactant, a gas hydrate inhibitor, any derivative thereof, and any combination thereof. 